U.S. patent application number 13/300247 was filed with the patent office on 2012-03-15 for detecting and correcting unintended fluid flow between subterranean zones.
This patent application is currently assigned to LANDMARK GRAPHICS CORPORATION. Invention is credited to Eric J. DAVIS, Scott D. MARSIC, Glenn R. MCCOLPIN, Etienne M. Samson, Ronald E. SWEATMAN.
Application Number | 20120061084 13/300247 |
Document ID | / |
Family ID | 48430066 |
Filed Date | 2012-03-15 |
United States Patent
Application |
20120061084 |
Kind Code |
A1 |
SWEATMAN; Ronald E. ; et
al. |
March 15, 2012 |
Detecting and Correcting Unintended Fluid Flow Between Subterranean
Zones
Abstract
Detecting and correcting unintended fluid flow between
subterranean zones. At least some of the illustrative embodiments
are methods including: injecting a first fluid into a subterranean
zone, the injecting by way of a first borehole; making a reading
indicative of surface deformation; identifying, based on the
reading indicative of surface deformation, a flow path for a second
fluid out of the subterranean zone; placing a compound into the
flow path, the compound reduces the flow of the second fluid
through the flow path.
Inventors: |
SWEATMAN; Ronald E.;
(Montgomery, TX) ; MCCOLPIN; Glenn R.; (Katy,
TX) ; DAVIS; Eric J.; (El Cerrito, CA) ;
MARSIC; Scott D.; (Oakland, CA) ; Samson; Etienne
M.; (Cypress, TX) |
Assignee: |
LANDMARK GRAPHICS
CORPORATION
Houston
TX
|
Family ID: |
48430066 |
Appl. No.: |
13/300247 |
Filed: |
November 18, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12875235 |
Sep 3, 2010 |
|
|
|
13300247 |
|
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Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
Y02C 20/40 20200801;
Y02C 10/14 20130101; E21B 41/0064 20130101; E21B 33/138 20130101;
E21B 47/10 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method comprising: injecting a first fluid into a subterranean
zone, the injecting by way of a first borehole; and then making a
reading indicative of surface deformation; identifying, based on
the reading indicative of surface deformation, a flow path for a
second fluid out of the subterranean zone; and placing a compound
into the flow path, the compound reduces the flow of the second
fluid through the flow path.
2. The method of claim 1 wherein placing the compound further
comprises injecting the compound through a borehole, wherein the
compound is configured to chemically react and thereby reduce flow
of the second fluid.
3. The method of claim 2 wherein injecting the compound through the
borehole further comprises at least one selected from the group
consisting of: injecting through a borehole designated for
injection of secondary recovery fluids; injecting through a
borehole designated for hydrocarbon extraction; and injecting
through a borehole drilled to intersect the flow path.
4. The method of claim 1 wherein injecting the first fluid further
comprises sequestering carbon dioxide in the subterranean zone.
5. The method of claim 1 wherein injecting the first fluid further
comprises injecting the first fluid to increase hydrocarbon
production from the subterranean zone.
6. The method of claim 5 wherein injecting the first fluid further
comprises injecting at least one selected from the group consisting
of: steam; carbon dioxide; water; and air.
7. The method of claim 1 wherein placing the sealing compound
further comprises placing a compound that lodges within the flow
path and thereby reduces flow of the second fluid.
8. The method of claim 7 wherein placing further comprises placing
a compound that chemically reacts with the second fluid to
viscosify into a reduced permeability mass.
9. The method of claim 1 wherein making a surface deformation
reading further comprises making interferometric synthetic aperture
radar measurements of surface elevation.
10. The method of claim 1 wherein making a surface deformation
reading further comprises: making global positioning system (GPS)
based measurements of position of floating vessels; and making
position measurements of measurement devices disposed on a seabed,
the position measurement based on signals broadcast by the floating
vessels.
11. The method of claim 10 wherein making position measurements
further comprises reading position of a plurality of inclinometers
disposed at seabed.
12. The method of claim 1 wherein making a surface deformation
reading further comprises taking readings from at least one
inclinometer disposed within a borehole proximate the subterranean
zone.
13. The method of claim 1 wherein making a surface deformation
reading further comprises combining the readings from two or more
measurement types to determine the surface deformation, the two or
more measurement types selected from the group consisting of:
global positioning system (GPS) based measurements of elevation of
a plurality of floating vessels; acoustic-based position
measurements of a plurality of measurement devices disposed on the
seabed; and inclinometer-based measures of change in surface
inclination.
14. A method comprising: injecting a first fluid into a
subterranean zone, the injecting by way of a first borehole, and
the subterranean zone residing at least partially below a body of
water disposed on a surface of the earth; and then making a reading
indicative of deformation of a portion of a seabed above the
subterranean zone; identifying, based on the reading indicative of
deformation, a flow path for a second fluid out of the subterranean
zone; and placing a compound into the flow path, the sealing
compound reduces the flow of the second fluid through the flow
path.
15. The method of claim 14 wherein injecting the first fluid
further comprises sequestering carbon dioxide in the subterranean
zone.
16. The method of claim 14 wherein injecting the first fluid
further comprises injecting the first fluid to increase hydrocarbon
production from the subterranean zone.
17. The method of claim 14 wherein making a reading indicative of
deformation of the surface further comprises: making global
positioning system (GPS) based measurements of position of a
plurality of floating vessels; and making position measurements of
a plurality of measurement devices disposed on the seabed, the
position measurement utilizing the floating vessels.
18. The method of claim 17 wherein making position measurements
further comprises reading position of a plurality of inclinometers
disposed at seabed.
19. The method of claim 17 wherein making position measurements
further comprises making position measurements using acoustic
signals propagated through the water between the plurality of
floating vessels and the measurement devices.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of application
Ser. No. 12/875,235 filed Sep. 3, 2010, titled "Detecting and
correcting unintended fluid flow between subterranean zones", which
application is incorporated by reference herein as if reproduced in
full below.
BACKGROUND
[0002] In the production of hydrocarbons, particularly natural gas,
a significant amount of carbon dioxide is also produced from
underground formations. The carbon dioxide is separated from the
hydrocarbons as part of the refining process. Some of the carbon
dioxide is used for other purposes, such as formation fracturing
operations and enhanced oil recovery, but the remaining carbon
dioxide is disposed of in some fashion. One technique is to inject
the carbon dioxide back into an underground formation for permanent
storage, known as sequestering. These and other sources of carbon
dioxide are also being stored underground to reduce greenhouse gas
emissions.
[0003] Sequestering carbon dioxide carries a risk that the
sequestered carbon dioxide will escape out of the underground
formation into other formations, like formations containing
drinking water, or escape to the surface. As of the writing of this
specification, the inventors are not aware of any sustained
instance where sequestered carbon dioxide has escaped to the
surface or contaminated a drinking water formation; however,
temporary leaks have occurred and any method that could be employed
to detect a leak, and stop any such leak, would be beneficial.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] For a detailed description of exemplary embodiments,
reference will now be made to the accompanying drawings in
which:
[0005] FIG. 1 shows a perspective cut-away view of a plurality of
subterranean zones and related monitoring equipment, in accordance
with at least some embodiments;
[0006] FIG. 2 shows a perspective cut-away view of a plurality of
subterranean zones and related monitoring equipment after injection
of a fluid in one of the subterranean zones, in accordance with at
least some embodiments;
[0007] FIG. 3 shows a perspective cut-away view of a plurality of
subterranean zones and related monitoring equipment after a leak
has formed between the subterranean zones, in accordance with at
least some embodiments;
[0008] FIG. 4 shows a perspective cut-away view of a plurality of
subterranean zones to discuss remediation through existing
boreholes, in accordance with at least some embodiments;
[0009] FIG. 5 shows a perspective cut-away view of a plurality of
subterranean zones and related monitoring equipment after the flow
path of the leak has been intercepted by a borehole, in accordance
with at least some embodiments;
[0010] FIG. 6 shows a drilling system to intersect a flow path, in
accordance with at least some embodiments;
[0011] FIG. 7 shows a wireline logging system used to help
intersect a flow path, in accordance with at least some
embodiments;
[0012] FIG. 8 shows a perspective cut-away view of a plurality of
subterranean zones and related monitoring equipment, including at
least some monitoring equipment within boreholes, in accordance
with at least some embodiments;
[0013] FIG. 9 shows a perspective cut-away view of an off-shore
system and related monitoring equipment, in accordance with at
least some embodiments;
[0014] FIG. 10 shows a method in accordance with at least some
embodiments.
NOTATION AND NOMENCLATURE
[0015] Certain terms are used throughout the following description
and claims to refer to particular system components. As one skilled
in the art will appreciate, oilfield service companies may refer to
a component by different names. This document does not intend to
distinguish between components that differ in name but not
function.
[0016] In the following discussion and in the claims, the terms
"including" and "comprising" are used in an open-ended fashion, and
thus should be interpreted to mean "including, but not limited to .
. . ." Also, the term "couple" or "couples" is intended to mean
either an indirect or direct connection. Thus, if a first device
couples to a second device, that connection may be through a direct
connection or through an indirect connection via other devices and
connections.
[0017] "Sequestering" shall mean placing in a particular location
for storage purposes, but shall not imply a time frame for the
storage, nor shall sequestering be obviated by leaks from the
particular location.
[0018] "Surface" shall mean the outermost portion of the crust of
the Earth. Surface shall include not only exposed crust, but
"surface" shall also include the seabed and/or the bottom of any
body of water.
[0019] "Disposed at the seabed", in reference to a measurement
device, shall mean that the measurement device resides at a
location being between two meters above the seabed and 30 meters
below the seabed. "Seabed" shall not speak to the salinity of the
water, and even a freshwater lake shall have a "seabed" for
purposes of this disclosure and the claims.
[0020] "Real-time", with respect to position determinations, shall
mean a position determination within 30 seconds or less of a
trigger event (e.g., a beginning a software routine that calculates
position based on GPS signals).
DETAILED DESCRIPTION
[0021] The following discussion is directed to various embodiments
of the invention. Although one or more of these embodiments may be
preferred, the embodiments disclosed should not be interpreted, or
otherwise used, as limiting the scope of the disclosure, including
the claims. In addition, one skilled in the art will understand
that the following description has broad application, and the
discussion of any embodiment is meant only to be exemplary of that
embodiment, and not intended to intimate that the scope of the
disclosure, including the claims, is limited to that
embodiment.
[0022] Furthermore, the various embodiments were developed in the
context of sequestering carbon dioxide in subterranean zones, and
thus the description that follows is based on the developmental
context. However, the methods and systems described may be used
regardless of the type of fluid injected into a subterranean zone,
and regardless of the reason for the injection. For example, the
various methods and systems find use in sequestering of other
fluids, and find use in injecting for other reasons (e.g.,
secondary recovery operations), and thus the developmental context
shall not be read as a limitation as to the scope of the claims.
Moreover, the various techniques are applicable both in land-based
operations, as well as offshore operations. So as not to unduly
complicate the discussion, the specification first addresses
land-based operations, and then specific concepts regarding
offshore operations. The application is related to two Society of
Petroleum Engineers (SPE) Paper No. 137843 by Ronald Sweatman et
al. titled "New Approach and Technology for CO.sub.2 Flow
Monitoring and Remediation", as well as SPE Paper No. 138258 by
Ronald Sweatman et al. also titled "New Approach and Technology for
CO.sub.2 Flow Monitoring and Remediation." Moreover, the
application is related to a Carbon Management Technology Conference
(CMTC) Paper No. 150980 by Ronald Sweatman et al. titled "New
Technology for Offshore CO2 Reservoir Monitoring and Flow
Control."
[0023] FIG. 1 shows a perspective cut-away view of a land-based
hydrocarbon producing field in order to explain concepts used in
the various embodiments. In particular, FIG. 1 shows a section of
earth 100 into which a borehole 102 has been drilled. In accordance
with at least some embodiments, the borehole 102 is at least
partially cased, and a portion of the casing that abuts
subterranean zone 104 is perforated to allow fluid communication
between the borehole and subterranean zone 104. Although FIG. 1
shows a derrick 107 associated with the borehole 102, in many cases
the derrick 107 will have been removed and only a valve stack and
related piping will denote the wellhead at the surface.
[0024] In some embodiments, the subterranean zone 104 is a zone of
porous rock that contains or contained hydrocarbons. Several
factors work together to create a subterranean zone, including not
only the porous rock, but also a substantially impermeable rock
layer 106 capping the zone 104, thus trapping the hydrocarbons
within the subterranean zone 104. For that reason, in some cases
the rock layer 106 is referred to as a "cap rock" layer.
Illustrative FIG. 1 also shows a second subterranean zone 108 which
may be capped by the same or a different cap rock layer. The
importance of the second subterranean zone 108 will be discussed in
relation to unintended flow paths out of illustrative subterranean
zone 104, which may also be referred to as leaks, the discussion in
greater detail below.
[0025] When fluids such as hydrocarbons are removed from a
subterranean zone, slight surface deformation may take place, and
in particular subsidence. Conversely, when fluids are injected into
a subterranean zone, slight surface deformation may take place, and
in particular surface swelling or rising. Surface deformation
responsive to injecting of fluids into illustrative subterranean
zone 104 is in most cases linearly proportional to the volume of
fluid injected and inversely proportional to approximately the
square of the depth. Different types of rock formations may have
greater or lesser response to injected fluids. Given the depth of
most subterranean zones in which carbon dioxide may be sequestered,
even for high volumes of injected carbon dioxide the amount of
surface deformation may be on the centimeter scale, and in many
cases on the millimeter scale or smaller.
[0026] In accordance with the various embodiments, at or near the
surface 110 resides a plurality of illustrative devices used to
detect surface deformation. For example, the illustrative system of
FIG. 1 shows a plurality of deformation measurement devices 112
(three such devices labeled 112A, 112B and 112C, but additional
devices shown but not numbered) in the form of Global Positioning
System (GPS) based measurements. The GPS-based measurement devices
112 make elevation measurements based on signals from a
constellation of satellites that orbit the earth. In many cases,
calculating absolute elevation based on signals from GPS satellites
alone will not result in elevation calculations to the centimeter
or millimeter scale. Thus, in accordance with at least some
embodiments the illustrative deformation measurement devices 112
also use signals from a comparative surface-based station 114,
which enables differential GPS-based deformation measurements to
the centimeter and/or millimeter scale, and in some cases with
accuracies of two millimeters or less.
[0027] Still referring to FIG. 1, the illustrative system of FIG. 1
also shows a plurality of deformation measurement devices 116
(three such devices labeled 116A, 116B and 116C, but additional
devices shown but not numbered) in the form of inclinometer-based
measurements (labeled TM for "tilt meter") placed proximate to the
surface. The inclinometer-based measurements may be made at the
surface in some cases, and in yet other cases the measurement
devices 116 may be placed within 6 to 12 meters of the surface (yet
still be considered proximate to the surface). The
inclinometer-based devices 116 do not measure absolute elevation,
but instead, when multiple measurements are made over time, provide
an indication of changes in tilt or incline of the sensor. If the
sensor is permanently or semi-permanently coupled at or near the
surface of the earth, then indications of tilt or incline of the
earth's surface may be made. Inclinometer-based devices have
resolutions that can detect changes in inclination when surface
deformations are much smaller than the millimeter scale, and in
particular in some cases the inclinometer-based measurements are
made with resolutions to 0.00000005 degrees.
[0028] Inclinometer-based readings provide high precision and
accuracy over short periods of time extending to several months,
but with current technology and deployment cannot provide high
accuracy over significantly longer periods. Thus in some
embodiments the GPS-based deformation measurement devices are
combined with inclinometer-based measurement devices such that high
accuracy is maintained over periods of time exceeding several
months.
[0029] FIG. 1 further illustrates a satellite 120. In accordance
with yet further embodiments, satellite 120 is used to take
interferometric synthetic aperture radar (InSAR) measurements of
surface deformation over the subterranean zone 104. While FIG. 1
illustrates the InSAR measurements by way of a satellite, in other
embodiments InSAR may be taken from airplane-based platforms,
tower-mounted stations or stations that take advantage of natural
terrain features to provide a direct view of the ground surface
under study. InSAR measurements perform centimeter scale or better
measurements of change in elevation. In some cases, such as the
RADARSAT-2 SAR platform, InSAR can have a three meter pixel size,
and a single set of synthetic aperture readings may cover an area
of up to 100 kilometers by 100 kilometers. Larger images may be
made by splicing together multiple sets of readings. The power of
InSAR is determining a change in surface deformation, where a first
SAR measurement is taken, and some time later (in accordance with
the various embodiments hours or days), a second SAR measurement is
taken. Though InSAR cannot determine actual elevation, changes in
elevation between measurements can be very accurately determined,
including changes in elevation on the millimeter scale. In some
embodiments, permanent or semi-permanent reflectors may be placed
to help ensure good InSAR readings (such as when surface vegetation
covers the area or changes, or where the area is subject to snow
accumulations).
[0030] GPS-based measurements, inclinometer-based measurements, and
InSAR-based measurements are used in the related-art, but for a
different purpose than in the various embodiments. In particular,
for some hydrocarbon producing underground formations, a secondary
recovery technique is used whereby steam is injected into the
formation through one borehole in an attempt to increase
hydrocarbon production (usually oil) from the same or a second
borehole in relatively close proximity. However, because of the
nature of the well construction and formation in which steam
injection as a secondary recovery technique is used, the steam
occasionally finds its way to the surface. In the related-art, one
or a combination of the GPS-based measurements, inclinometer-based
measurements, and InSAR-based measurements are used to predict
locations where secondary recovery steam is about to break the
surface, and to determine from which borehole the steam was
injected. As mentioned above, the amount of surface deformation is
approximately inversely proportional to the square of the depth,
and thus the amount of localized deformation for steam close enough
to break the surface is relatively high compared to surface
deformation associated with a deep subterranean zone. Moreover, the
techniques related to surface deformation are used to trace the
steam back to the steam injection borehole, such that the steam
injection can be stopped and/or the borehole permanently shut in.
An illustrative service provider for providing GPS-based
measurements, inclinometer-based measurements and/or InSAR-based
measures is the PINNACLE.TM. brand service provided by Halliburton
Energy Services, Inc, of Houston, Tex.
[0031] It is noted that one of ordinary skill in the art is aware
of the GPS-based measurements, inclinometer-based measurements, and
InSAR-based measurements (in the context noted in the immediately
preceding paragraph), and thus so as not to unduly complicate this
description and to avoid obscuring the various embodiments, a more
detailed discussion of each measurement technology is omitted.
[0032] Now consider the situation where illustrative carbon dioxide
is pumped or injected into the subterranean zone 104. In most
situations, the carbon dioxide is under sufficient pressure to be a
super-critical fluid, but having the carbon dioxide in this phase
is not required. The additional volume in the subterranean zone 104
creates a surface deformation 200 as illustrated in FIG. 2. The
deformation 200 illustrated in FIG. 2 is greatly exaggerated for
purposes of clarity. Again, in most case the amount of surface
deformation will be a centimeter or less, and in many cases the
surface deformation will be merely a few millimeters. Nevertheless,
in accordance with the various embodiments a surface deformation
reading is made during and/or after the carbon dioxide is injected,
the surface deformation reading by one or more of GPS-based
measurements, inclinometer-based measurements, InSAR-based
measurements, and/or any other technology that directly or
indirectly measures surface deformation. In the illustrative case
of FIG. 2, the sequestered carbon dioxide is fully contained within
the subterranean zone 104.
[0033] However, for a variety of reasons, the sequestered carbon
dioxide may escape or leak from the subterranean zone 104. The leak
creates a flow path for fluids out of the subterranean zone 104.
The fluid that leaks from a subterranean zone may be different in
each situation. If the leak path is on the fringes of the
subterranean zone relatively far from the injection point of the
carbon dioxide, the leaking fluid may be a constituent fluid of the
subterranean zone, such as hydrocarbons or water. On the other
hand, if the leak is near the injection point, or substantially all
the hydrocarbons have been removed from the subterranean zone, then
the leaking fluid may be the sequestered carbon dioxide. Yet
further still, depending on how long the leak occurs, the leaking
fluid may change from a constituent fluid of the subterranean zone
to carbon dioxide.
[0034] In accordance with the various embodiments, the surface
deformation readings are used to determine whether there is a leak
of the sequestered fluid out of the subterranean zone 104. With
respect to determining whether sequestered fluid is or has escaped,
consider FIG. 3. In particular, FIG. 3 illustrates a situation
where a flow path 300 develops between the illustrative
subterranean zone 104 and illustrative subterranean zone 108. There
may be a variety of reasons for a leak between subterranean zones.
For example, the sub-surface deformation caused by the increased
volume of fluids by sequestering in a subterranean zone may cause
flow pathways to open in poorly sealed wells or between layers of
rock that were previously sealed by the great weight above the
layers. Moreover, such subsurface deformation may cause cracking
and fissures to form, which then may open flow paths between the
subterranean zones. Yet further still, natural geological faults
may be pre-existing between the subterranean zones, and increased
pressures within the first subterranean zone may force fluids along
the pre-existing geological fault.
[0035] Making a determination that the subterranean zone is
developing or has developed a leak may take many forms depending on
the particular situation. For example, after a sufficient amount of
fluid has leaked from the subterranean zone 104, the surface
deformation readings over the subterranean zone 104 may show
subsidence. Such subsidence after swelling that corresponds with
injection of the sequestered fluid may be indicative of a leak.
Likewise, in some cases the fluid wave front moving through flow
path 300 may itself cause surface deformation that is detectable,
such as by illustrative GPS-based measurement station 112D,
inclinometer-based measurement station 116D, or InSAR-based
measurements scanning areas beyond the surface above the
subterranean zone 104. Yet further still, the fluid moving into
subterranean zone 108 may cause surface deformation 302, which may
be detected by ground-based measurement devices (if present), or
InSAR-based measurements scanning areas beyond the surface above
the subterranean zone 104.
[0036] The frequency of measurement of surface deformation may
differ for each circumstance. For example, in cases where a leak is
unlikely, inclinometer-based measurements may be taken only every
few weeks or months; however, once any measurement system gives an
indication that a leak has developed or may be developing, the
frequency of some or all the measurements may increase. In some
cases, when checking for a leak from a subterranean zone,
inclinometer-based measurements and GPS-based measurements may be
taken every hour. Greater or lesser time intervals for measurements
may be equivalently used, but such intervals are still more
frequent than surface-based observations used for other systems
(such as to monitor secondary recovery injection fluids). A risk
assessment is used to determine the initial time intervals where a
high risk situation requires a higher frequency of measurements,
and vice-versa.
[0037] Regardless of the precise mechanism by which the leak is
detected, in most cases the general direction of the leak will be
known based on the detection of the leak, or the direction of the
leak could be solidified by further measurements (e.g., installing
and/or activating additional ground-based measurement stations,
expanding the sweep area of the InSAR-based measurements). In some
cases, knowing the general direction of the leak may directly
indicate the flow path for the leak, for example knowing the
general leak direction in combination with existing seismic data
may directly indicate the flow path as being along a known
geological fault.
[0038] Once a leak has been detected, remediating the leak may take
many forms depending on the particular situation. Consider, for
example, a situation illustrated by FIG. 4. In particular, consider
that borehole 102 associated with subterranean zone 104 is used as
the injection point for secondary recovery fluids associated with
producing borehole 400. For example, the operator may inject carbon
dioxide or water into the subterranean zone 104 by way of borehole
102 in an attempt to increase the hydrocarbon production from
borehole 400. Further consider that borehole 402 associated with
subterranean zone 108 is likewise a hydrocarbon producing borehole,
but the operator does not want the secondary recovery fluid
injected at borehole 102 to affect borehole 402. Finally, consider
that a leak through flow path 300 has developed.
[0039] In the illustrative situation of FIG. 4, remediating the
leak may take many forms. In some embodiments, the operator may
utilize any of a variety of sealants or flow modifying compounds
injected through either the borehole 102 or the "bullheaded"
through production piping associated with borehole 402. For
example, the operator may inject a flow a compound into borehole
102, where the flow modifying compound selected is configured to
chemically react upon contact with the hydrocarbons associated with
subterranean zone 108. Thus, as the injected compound moves along
the flow pathway 300, at some point the compound chemically
contacts the fluids associated with the subterranean zone 108 and a
chemical reaction takes place, which chemical reaction reduces
and/or seals the flow along the flow pathway 300.
[0040] In yet still other cases, the compound may be selected to
chemically react with the fluid in the subterranean zone 104 and
may be injected through borehole 402 (e.g., "bullheaded" through
production tubing). As the compound migrates toward the leak flow
path 300 (and in this example a "reverse" flow), the compound
contacts the fluid associated with subterranean zone and chemically
reacts, which chemical reaction reduces and/or seals the flow along
the flow pathway 300. In yet still other cases, the compound
selected and pumped into a borehole may be chemically reactive with
the fluid in the associated subterranean zone, but may be buffered
with other fluids to ensure that compound reaches the leak flow
path. In yet still other cases, the compound selected may be "self"
activated in the sense that the compound, when triggered, has a
slow moving chemical reaction timed to finalize or complete when
the compound reaches the leak flow pathway 300.
[0041] Regardless of the borehole into which the compounds are
injected with a goal toward reducing the flow through or sealing
the leak flow pathway 300, the chemical reactions themselves may
likewise take many forms. In some cases, reducing the flow or
sealing the leak flow pathway may be "mechanical" in the sense that
the compound in the leak flow pathway 300, partially or fully
physically blocks the leak flow pathway 300. For example, in the
illustrative case of contact with carbon dioxide being the trigger,
one may send a latex- or a silicate/polymer-based sealant that
converts from a pumpable liquid to an un-pumpable rigid or
semi-rigid sealant. In the illustrative case of contact with water
being the trigger, the compound may comprise a micro-fine Portland
cement mixed in a non-aqueous carrier fluid (e.g., diesel, mineral
oil, or synthetic oil) with surfactants. Thus, when the compound
contacts water, the cement chemically reacts and hardens in place,
reducing the flow or sealing the leak flow pathway. Stated
otherwise, the compound viscosifies into a reduced permeability
mass.
[0042] Further with respect to "mechanical" compounds, now consider
a situation where the fluid escaping along the flow path 300 is
hydrocarbon. In such an illustrative situation, the compound placed
in the flow path 300 may be an organophyllic, micro-fine clay
suspended in a water-based fluid. While suspended in the
water-based fluid, the clay lodges in the cracks and fissures that
define the flow path 300. However, when the hydrocarbons displace
the water that suspended the clay, the clay absorbs hydrocarbons
and swells, thus further reducing the escape of hydrocarbons along
the flow path 300.
[0043] Thus, the compound placed in the flow path 300 may comprise
a particulate material such as cement, sand, silica flour,
gilsonite, graphite; fibrous materials, flaky materials, granular
materials or combinations thereof; polymeric materials, a
water-soluble material such as a starch, a starch mixture, a
pregelatinized starch, a chemically modified starch, a naturally
occurring starch or combinations thereof; a hydrophobically
modified polymer; or combinations thereof.
[0044] In other cases, however, reducing the flow or sealing the
leak flow pathway may be "chemical" in the sense that the compound
alters the molecular interactions between the rock and the fluids.
For example, most hydrocarbon producing subterranean zones are
"water wet", meaning that there is little or no affinity for the
molecular interactions between elements of the hydrocarbon and
elements of the surrounding rock, thus enabling movement of
hydrocarbons through pore spaces and stress fractures (keeping in
mind in many cases the pore spaces and stress fractures are micron
scale features). However, using any of a variety of related-art
chemical compounds, it is possible to change the "wetting" of a
rock formation to "oil wet", meaning the molecules of the formation
have an affinity for (attract and hold) hydrocarbon molecules, thus
reducing or eliminating the ability of the hydrocarbon molecules to
move through the pore spaces and stress fractures. The reverse
situation is also possible--changing an "oil wet" formation to a
"water wet" formation. Abstracting the "chemical" remediating
concept slightly, it is possible to chemically alter the relative
permeability of an earth formation, and such altering of the
relative permeability may be used to reduce the flow through or
seal the leak flow pathway 300.
[0045] Two points are in order before proceeding. First, one of
ordinary skill in the art is aware of various types compounds
discussed, and thus so as not to unduly complicate this description
and to avoid obscuring the various embodiments, a more detailed
discussion of each category of sealing compound is omitted.
Secondly, while one of ordinary skill may be aware of such
technologies, to the knowledge of the inventors herein, use of such
technologies has been as a mechanism to prevent loss of drilling
fluid into formations penetrated by a borehole, not with respect to
reducing or stopping a leak along a flow path 300 between
subterranean zones. In the context of preventing loss of drilling
fluid into formations, some commercially available sealing
compounds comprise FLEXPLUG.RTM. W (for formations containing
water), FLEXPLUG.RTM. OBM (for formations containing hydrocarbons),
and FLEXPLUG.RTM. R (for formations containing water and/or dry gas
flows), all available from Halliburton Energy Services, Inc., of
Houston, Tex.
[0046] The various embodiments discussed to this point have assumed
the compound used to remediate the leak flow path 300 is injected
through an existing borehole. However, in yet still other cases,
placing the compound used to reduce the flow through or seal the
leak flow pathway 300 may be more direct. FIG. 5 shows a system in
accordance with the alternative embodiments where a borehole is
drilled to intersect the flow path 300 of the leak. FIG. 5
illustrative shows the second borehole 500 drilled from a derrick
502. However, the presence of derrick 502 in illustrative FIG. 5
should not imply that the drilling of the borehole 500 must be
drilled by conventional techniques. Any suitable drilling system
and method may be used to create the second borehole 500, such as
drilling based on coiled tubing using a downhole "tractor".
Moreover, illustrative FIG. 5 shows the second borehole 500 to be
completely distinct from other boreholes (e.g., borehole 102);
however, in at least some embodiments the second borehole 500 may
be a branch borehole of the borehole through which the sequestered
fluid is injected into the subterranean zone 104, or any other
borehole including other injection/producing boreholes, as well as
monitor boreholes in the vicinity. Finally, in illustrative FIG. 5,
the second borehole 500 turns toward subterranean zone 104 to
intersect the leak flow path 300, but such is not required. The
second borehole 500 may equivalently turn toward the subterranean
zone 108, or in some cases intersection the flow path 300 of the
leak at or near right angles to the direction of fluid flow within
the flow path 300.
[0047] In accordance with at least some embodiments, the location
of the flow path 300 of the leak may be known in a general sense,
but the precise location may not be known or determinable from the
surface deformation measurements. In such cases, the drilling of
the second borehole may begin initially in the direction indicated
by the surface deformation measurements, but refining the drilling
direction to ensure intersection with the flow path 300 of the leak
may be made by tools disposed within the second borehole 500. In
particular, FIG. 5 shows a drilling system 600 that comprises drill
string 602 having a drill bit 604 on a distal end thereof. Rotary
motion of the drill bit 604, either caused by surface equipment 606
or by a downhole motor, creates the second borehole 500. In
accordance with the illustrated embodiments, the drill string 602
comprises a downhole tool 608, the downhole tool in most cases
relative close to the drill bit 604. The downhole tool 608 takes
measurements with the drill string 502 within the second borehole
500, and in many cases the measurements may be made while drilling
is taking place. Thus, downhole tool 608 may be referred to as a
logging-while-drilling (LWD) or measuring-while-drilling (MWD)
tool. Some in the industry assign distinctions between LWD and MWD,
with LWD in most cases referring to measuring of properties of the
formations surrounding the borehole, and MWD in most cases
referring to measuring properties associated with the borehole
itself or the drilling process (e.g., inclination of the borehole,
downhole pressure of the drilling fluid, temperature). However, the
terms are often used interchangeably, and for the balance of this
discussion the term LWD will be used with the understanding that
LWD also refers to MWD measurements.
[0048] In accordance with a particular embodiment, the drilling
direction for the second borehole 500 is refined during drilling by
use of LWD measurements of illustrative downhole tool 608. The type
of downhole tool 608 used varies depending on the particular
situation and the type of fluid moving along the leak flow path
300. In most cases, however, the downhole tool 608 is used to
detect contrast between properties of a rock formation in a volume
610 around the tool, where the contrast is with respect to
properties of rock formations where the fluid is moving compared to
rock formation free from the escaping fluid. There are a myriad of
possible situations, and rather than attempt to define each
possible situation, the specification gives a brief overview of
several different types of downhole tools that may be used.
[0049] One type of downhole tool 608 that may be used falls in the
class of tools known as "acoustic" tools. Acoustic tools emit an
acoustic signal that propagates through the surrounding formation.
In many cases the acoustic signal is in the high audible range and
above. The acoustic tool also has one or more "listening" devices
that detect portions of the acoustic signal as the signal
propagates through the formation. Acoustic tools in many cases
produce an indication of the speed of sound within the rock
formations, and also in many cases the speed of sound measurement
is azimuthally sensitive (i.e., directional in relation to the
rotation of the tool within the borehole). Thus, in combination
with a tool that determines or measures the rotational orientation
of the tool, an acoustic tool could identify the relative direction
and/or proximity to the flow path 300 of the leak based on changes
in speed of sound measured as a function of rotational orientation
of the drill string. For example, as the drill bit approaches a
rock boundary location where the lower rock formation contains the
leak flow path 300, the acoustic tool may identify the boundary
based on sensed changes in speed of sound at particular rotational
orientations of the tool. A variation of the an acoustic tool is
called a "noise log" where the tool does not send out acoustic
signals and only has sensitive listening devices to hear the sounds
made by dynamic flows in the surrounding rock formations. In
practice, this type of tool is coupled to a rotational orientation
device to find the direction to the source of the flow-induced
sounds. Some directional-sensing noise logging tools can detect
ultra-sonic sound waves caused by leaking fluids at various
distances away from the tool inside the surrounding rock and behind
multiple casing strings. Example noise logging tools are
manufactured by Seawell which are run in wells by Halliburton
Energy Services, Inc., of Houston, Tex.
[0050] Another illustrative type of downhole tool 608 that may be
used falls within the class of tools termed induction or
electromagnetic (EM) tools. EM tools launch or release
electromagnetic waves that propagate through the formation.
Portions of the electromagnetic waves are detected by sensors, and
based on the amplitude or phase of the detected electromagnetic
waves a variety of formation properties can be determined, such as
resistivity (and inversely conductivity). In many cases the EM
tools are azimuthally sensitive, and thus may detect approaching
bed boundaries (such as an approaching flow path 300) based on the
contrast in azimuthally sensitive conductivity readings above and
below the tool.
[0051] Another illustrative type of downhole tool 608 that may be
used falls within the class of tools termed conduction tools.
Conduction tools create voltage potential that causes electrical
current to flow from the tool, through the formation and back to
the tool. Based on the electrical properties to induce a particular
electrical current flow, attenuation of the current as the current
flows through the formation, and phase shift of the current as the
current flows through the formation, a variety of formation
properties may be determined, such as resistivity (and inversely
conductivity). In many cases the conduction tools are azimuthally
sensitive, and thus may detect approaching bed boundaries (such as
an approaching flow path 300) based on the contrast in azimuthally
sensitive conductivity readings above and below the tool.
[0052] Two points are in order before proceeding. First, one of
ordinary skill in the art is aware the various types of logging
tools, and thus so as not to unduly complicate this description and
to avoid obscuring the various embodiments, a more detailed
discussion of logging tools is omitted. Secondly, while one of
ordinary skill may be aware of such technologies, to the knowledge
of the inventors herein, use of such technologies has not been with
respect to intersecting a flow path 300 of a leak between
subterranean zones, or intersecting with the ultimate goal of
remediating the leak through the flow path. An illustrative set of
logging tools that may be used comprises EWR.RTM.-PHASE 4
resistivity measurements, InSite ADR.TM. Azimuthal Deep
Resistivity, InSite AFR.TM. Azimuthal Focused Resistivity, M5.TM.
Integrated LWD, all available from Halliburton Energy Services,
Inc., of Houston, Tex.
[0053] Moreover, while the specification highlights three broad
categories of logging tools, many variations of the three broad
categories are possible, and the high level descriptions should not
be read as a limitation as to the configuration of tools that may
be selected to help refine the drilling direction to ensure the
second borehole 500 intersects the flow path 300. For example, some
conduction tools may be self contained a short distance from the
drill bit, while other conduction systems utilize the drill bit
itself as the launch location for electrical current, thus focusing
the conduction-based measurement more along the drilling direction.
Moreover, the depth of measurement of each tool changes as a
function of the tool type and particular tool configuration. Thus,
in refining the drilling direction multiple tools may be used,
first using a tool that interrogates a larger volume 610 of the
formation surrounding the borehole 500 (but in most cases with
lower spatial resolution for data obtained), then using a tool that
interrogates a smaller volume 610 of the formation surrounding the
borehole 500 (but with higher spatial resolution of the data), and
so on. Further still, multiple tools, including tools of varying
operational type, may be simultaneously used to help refine the
drilling direction.
[0054] The various embodiments to this point have described the
refining of the drilling direction in a LWD sense; however, the
refining of the drilling direction need not be limited to LWD
tools. FIG. 6 shows other embodiments where the downhole tool used
to refine the drilling direction is a wireline tool 700. In
particular, in the situation illustrated by FIG. 7 the drill string
has been removed or "tripped" from the borehole 500, and a tool 700
lowered into the borehole 500. The tool 700 comprises a pressure
vessel within which various sensors and electronic devices are
placed, and the tool is suspended within the borehole by a wireline
or cable. Where the borehole 500 has a horizontal portion, it may
be difficult to move the tool 700 into the horizontal portions; and
thus, in some embodiments tubing 702 (such as coiled tubing, or
jointed pipe) is used. In particular, the wireline or cable is
placed in operational relationship to the tubing (e.g., within the
internal diameter), and thus force to move the tool 700 into
horizontal portions may be supplied at the surface. In yet still
other cases, the tool 700 may itself implement a physical system to
move within the horizontal portions. Regardless of the mechanism to
transfer the tool 700 within the horizontal portions, the cable
communicatively couples the tool 700 to surface equipment 704. Like
the LWD tools, the wireline tool 700 interrogates a volume 710
around the tool, and different tools may interrogate different
volumes during the process of refining the drilling direction. The
types of measurements that may be made with tool 700 are the same
as those discussed with respect to the LWD tools discussed
above.
[0055] While the various embodiments of refining drilling direction
to intersect the flow path 300 of the leak have been in relation to
LWD and wireline tools, the logging methods are not limited to LWD
and wireline, as other logging techniques may be additionally or
equivalently used. For example, in some embodiments may
additionally use what is termed "mud logging" to help refine
drilling direction. In one aspect of mud logging, the drilling
fluid that returns to the surface is analyzed to determine the
presence of components that entered the drilling fluid down hole.
For example, if the fluid escaping along the flow path 300 is
carbon dioxide, an increase in carbon dioxide in the drilling fluid
that returns to surface would confirm that the second borehole 400
has intersected the flow path 300. Similar analysis may be
performed for any fluid escaping along the flow path 300.
[0056] As yet another example, the cuttings that are carried to the
surface in the drilling fluid can be analyzed to determine their
mineralogical and/or elemental content. If the flow path 300 of the
leak resides within a known type of rock (e.g., known based on
previous seismic work in the area or survey wells), when analysis
of the cuttings show an increase in the type of rock through which
the flow path 300 is known to reside, such may indicate that the
second borehole 400 has intersected the flow path 300. Use of
logging devices and systems as described is merely illustrative,
and one of ordinary skill, now understanding the goal of
intersection for purposes of remediating a leak between
subterranean zones, could select a suite of logging tools to refine
the direction of the intersecting borehole based on the particular
situation presented.
[0057] Returning to FIG. 5, once the second borehole 500 has
intersected the flow path 300, in accordance with the various
embodiments a sealing compound is placed in the flow path 300
through borehole 500. The compound may be any of the various
compounds discussed above, as well as combinations thereof.
[0058] With respect to making measurements of surface deformation,
the various embodiments discussed to this point have relied, at
least in part, on surface-based devices such GPS-based elevation
measurements, and inclinometer-based measurements. Moreover, the
InSAR-based readings again produce an indication of changes in
surface elevation. However, making a reading indicative of surface
deformation in accordance with the various embodiments is not
limited to just readings that are directly indicative of surface
deformation.
[0059] In accordance with at least some embodiments, measurements
may be taken in other locations, such as within boreholes proximate
to the subterranean zone, but in some cases closer to the
subterranean zone than the surface. In particular, FIG. 8 shows a
system similar to that of FIG. 2, but where in addition to
surface-based measurement devices 112 and 116, the system further
includes a plurality of sub-surface measurement devices 800 and
802. More particularly still, in accordance with at least some
embodiments, inclinometer-based measurement devices 800 and 802 may
be placed in respective boreholes 804 and 806. Illustrative
boreholes 804 and 806 may take many forms. In some cases the
boreholes 804 and 806 are dedicated monitoring boreholes drilled
specifically for monitoring the subterranean zone 104, such as for
permanently or semi-permanently installed seismic sensors. In yet
still other cases, the boreholes 804 and 806 may be active and/or
abandoned hydrocarbon producing wells. Regardless of the precise
nature of the boreholes 804 and 806, in some embodiments
inclinometers are placed within the boreholes closer to the
subterranean zone. In this way, the inclinometer-based measurements
are more sensitive to the location of the injected fluid plume, and
leaks, yet such measurements are still indicative of surface
deformation. Deformation information for all the measurement
devices may be combined when determining whether a leak from the
subterranean zone 104 exists, and/or the direction of the leak.
[0060] The various embodiments to this point have been in reference
to observing surface deformation of a non-submerged surface;
however, the various embodiments are also applicable to offshore
operations. FIG. 9 shows a perspective cut-away view of an offshore
hydrocarbon field in order to explain concepts used in the various
embodiments. In particular, FIG. 9 shows well head 900 associated
with a borehole (not specifically shown). The well head 900 is
illustratively associated with a floating vessel illustratively
shown as a platform 902. In the case of a completed well, the
platform 902 could be a production platform, or in more active
fields the platform 902 may be a drilling platform.
[0061] Like the land-based systems, a plurality of deformation
measurement devices 904 (three such devices labeled 904A, 904B and
904C, but additional devices shown but not numbered) in the form of
inclinometer-based measurements (again labeled TM for "tilt meter")
are placed proximate to the seabed 906. For purposes of this
disclosure and the claims the seabed 906 is the surface of the
earth that is covered with water. From a technological basis, the
measurement devices 904 may be the same as their land-based
brethren, but sealed in waterproof and pressure resistant
containers. The measurement devices 904 may be placed proximate the
seabed 906 in any suitable manner, such as by trenching, suction
anchors, gravity deployed anchors, within holes created by remotely
operated vehicles (ROVs) by way of an auger, or weighted systems.
In some cases, the inclinometer-based measurements may be made at
the seabed 906, and in yet other case the measurement devices 904
may be slightly above the seabed 906 with an anchor in some form
extending down into the seabed 904. Further still, the measurement
devices 904 may be buried some distance (within 20 to 40 feet of
the seabed), yet still be considered proximate to the surface.
[0062] Communication between the measurement devices 904 and the
computer system which makes surface deformation determinations may
take many forms. For example, the measurement devices may be
equipped with acoustic transmission devices which enable each
measurement device to periodically (e.g., minutely, hourly, daily,
or change driven) send its respective measurement to an acoustic
receiver, such as an acoustic receiver on the platform 902. The
acoustic communication with the platform is illustrated by acoustic
waves 907 emanating from measurement device 904A. A computer system
on the platform 902 in turn, makes the surface deformation
determinations, or the computer system sends the data to a
land-based station 908, such as by way of satellite 910. In other
cases, the measurement devices may be communicatively coupled to
the land-based station 908 by a communication cable 912. The
communication cable may take any suitable form, such as a
fiber-optic cable, electrical conductors, or combinations. In a
particular embodiment, the measurement devices 904 are disposed
within the communication cable such that deployment of the
communication cable 912 likewise deploys the measurement devices
904.
[0063] Communication of measured values is not limited to acoustic
communication with a platform or over a communication cable. In
other embodiments, the measurement devices may acoustically
communicate with any suitable vessel floating at or near the top of
water. For example, measurement device 904C is illustratively shown
acoustically communicating (by way of acoustic waves 914) with buoy
916. Illustrative buoy 916 may forward the readings using any
suitable system, such as point-to-point electromagnetic wave
communication, a cellular system, or communications using satellite
910.
[0064] For relatively shallow subterranean zones and/or short term
measurement of surface deformation (e.g., hours, days, a few
months), placing a plurality of inclinometer-based measurement
devices 904 at approximately known positions may be sufficient to
determine surface deformation. However, for deeper subterranean
zones and/or longer term measurements (e.g., months, years),
position of the measurement devices may need to be known. However,
because GPS signals cannot penetrate the water, direct GPS-based
positioning of the measurement devices is not available. Several
underwater positioning systems may be used to obtain position with
varying degrees of precision. Example positioning systems are
discussed next.
[0065] One such underwater positioning system uses acoustic waves
propagated through the water above the seabed 904. In particular,
an acoustic transmitter may be placed at a base location (e.g., the
wellhead 900). The transmitter may launch acoustic waves that
propagate through the water to the measurement devices 904. In some
embodiments, each measurement device 904 may be arranged to be or
have an acoustic reflector. The acoustic wave reflects from the
reflective portion of the measurement device, and is received back
at the base location. Based on the round trip time for the acoustic
wave and the speed at which acoustic waves travel through the water
(as a function of temperature, salinity), a distance between the
base location and each measurement device 904 may be determined. In
cases where the base location has an array of receivers, a relative
bearing from the location of the base station to the measurement
device may also be determined. In this illustrative case, once an
initial distance/bearing is determined, surface deformation may
change the slant-range distance and/or bearing between the base
location and the measurement device. Thus, changes in slant-range
distance and/or bearing, possibly in combination with changes in
incline at the measurement device, are indicative of surface
deformation at the location.
[0066] In other cases, each measurement device has a receiver to
receive the electromagnetic wave. Based on arrival time of the
electromagnetic wave, and possibly data encoded in the
electromagnetic wave (e.g., the precise time the electromagnetic
wave was launched), the measurement device itself may determine a
precise distance between the base station and the measurement
device. The measurement device 904 may provide the distance
determined through other communication means, such as through
acoustic communication with a floating vessel (e.g., platform 902,
or buoy 916), where computers on the floating vessel may utilize
the information, or forward the information to land-based station
908. Further still, in the case of measurement devices
communicatively coupled to the land-based station 908 by way of a
communication cable, the distance information may be forwarded by
way of the communicative coupling.
[0067] Another illustrative underwater positioning system uses
acoustic waves propagated through the seabed 904. In particular, an
acoustic transmitter may be placed at a base location (e.g., the
wellhead 900). The acoustic transmitter may launch acoustic waves
that propagate through the seabed to the measurement devices 904.
In some embodiments, each measurement device 904 may include a
seismic detector. The acoustic wave is detected by the seismic
detector, and based on arrival time of the acoustic wave at the
measurement device, a precise distance between the base location
and the measurement device 904 may be determined. In some cases,
the measurement device 904 itself may make the distance
determination, but in other cases acoustic wave arrival time
information is forwarded (e.g., through an acoustic system to a
floating vessel, or through a communicative coupling by way of a
cable) to one or more other computer systems for making the
distance determination. Once an initial distance between the base
location and the measurement device is determined, surface
deformation may change the slant-range distance between the base
location and the measurement device. Thus, changes in slant-range
distance, possibly in combination with changes in incline at the
measurement device, are indicative of surface deformation at the
location.
[0068] Another underwater positioning system uses electromagnetic
waves propagated through the seabed. In particular, an
electromagnetic transmitter may be placed at a base location (e.g.,
the wellhead 900). The transmitter may launch electromagnetic waves
that propagate through the seabed 906 to the measurement devices
904. In some embodiments, a measurement device 904 may include an
electromagnetic reflector. The electromagnetic wave reflects from
the reflector and is received back at the base location. Based on
the round trip time for the electromagnetic wave and the speed at
which electromagnetic waves travel through the sediment of the
seabed, a precise distance between the base location and each
measurement device 904 may be determined. In this illustrative
case, once an initial distance is determined surface deformation
may change the slant-range distance between the base location and
the measurement device. Thus, changes in slant-rage distance,
possibly in combination with changes in incline at the measurement
device, are indicative of surface deformation at the location.
[0069] In other cases, each measurement device has an acoustic
receiver to receive the acoustic positioning signal. In some
embodiments, the acoustic receiver for distance measurement may
also be used in bi-directional acoustic communication with one or
more floating vessels. Based on arrival time of the acoustic wave,
and possibly data encoded in the acoustic wave (e.g., the precise
time the acoustic wave was launched), the measurement device itself
may determine a precise distance between the base station and the
measurement device. The measurement device 904 may provide the
distance determined to other devices through other communication
means, such as through acoustic communication with a floating
vessel (e.g., platform 902, or buoy 916), where computers on the
floating vessel may utilize the information, or forward the
information to land-based station 908. Further still, in the case
of measurement devices communicatively coupled to the land-based
station 908 by way of a communication cable, the distance
information may be forwarded by way of the communicative
coupling.
[0070] Still referring to FIG. 9, in accordance with yet still
other embodiments, position (including an elevation) may be
determined using a plurality of floating vessels. In particular,
each illustrative floating vessel in FIG. 9 (i.e., platform 902,
and buoys 916, 918, and 920) may determine their respective
real-time geospatial position (including elevation) based on
signals received from GPS satellites and land-based station 114
and/or terrestrial radio systems used for position determination.
Each floating vessel, in turn, may acoustically broadcast a timing
signal and position information to the measurement devices 904. The
measurement devices, receiving the plurality (e.g., four or more)
acoustic signals from the floating vessels may determine a precise
geospatial location. That is, taking into account relative arrival
time of the signal from each floating vessel, position of each
floating vessel when the acoustic signal was launched (embedded in
the acoustic signal), and the speed of sound in the water, each
measurement device may calculate a geospatial location (including
elevation).
[0071] With respect to the floating vessels, once a device has
"locked" to a series of GPS satellite signals, calculating position
may occur very quickly (tens of milliseconds or less). Thus, in
calm seas very little change in absolute elevation of a floating
vessel may occur between determining position (and elevation), and
acoustically broadcasting the position to the measurement devices
904. However, in high seas, position of the floating vessel may
change rapidly, making the determination of position by the
measurement devices less accurate. Moreover, in extremely high
seas, reception of GPS signals from satellites near the horizon may
be sporadic, adversely affecting the ability of the measurement
devices 904 to determine position. However, since surface
deformation is a relatively slow process, the presence of a surface
deformation may be made based on data spanning days, weeks, or
months, a temporary inability to precisely calculating position
because of high seas does not render the system unusable.
[0072] In the case of surface deformation for a surface covered by
water, InSar measurements may not be available. However, an
inability to use an InSAR-type system may be compensated for by the
increased numbers of measurement devices, or installation of
additional devices when a leak is determined. For example, if an
offshore carbon dioxide sequestration operation starts to show
subsidence, a leak may be assumed and thus additional (possibly
temporary) measurement devices may be installed to identify the
direction the leak is proceeding.
[0073] Once a flow path out of an offshore subterranean zone is
determined, any of the remediation techniques described above may
used, including in appropriate circumstances using drilling
platforms to drill new boreholes to intersect the flow pathway.
However, given the high cost of drilling additional boreholes, in
many situations remediation through existing boreholes (whether
hydrocarbon producing or for injection of secondary recovery
fluids) will be chosen.
[0074] FIG. 10 illustrates a method in accordance with at least
some embodiments. In particular, the method starts (block 1000) and
proceeds to: injecting a first fluid into a subterranean zone, the
injecting by way of a first borehole (block 1002); making a reading
indicative of surface deformation (block 1004); identifying, based
on the surface deformation reading, a flow path for a second fluid
out of the subterranean zone (block 1006); and placing a compound
into the flow path, the compound reduces the flow of the second
fluid through the flow path (block 1010). Thereafter, the method
ends (block 1012).
[0075] The above discussion is meant to be illustrative of the
principles and various embodiments of the present invention.
Numerous variations and modifications will become apparent to those
skilled in the art once the above disclosure is fully appreciated.
For example, while discussed in terms of sequestration of carbon
dioxide, the identification of leaks using surface deformation, and
sealing the leak may be used for any type of sequestration, as well
for non-sequestration uses such as secondary recovery techniques
that inject any suitable fluid, such as steam, carbon dioxide,
water, nitrogen, natural gas, waste water and/or air. Further
still, while the various embodiments rely on measures of surface
deformation, such measures can be augmented by other data, such as
real-time temperature and pressure data from wells instrumented
with sensors connected to fiber optic cables, geophones and/or
accelerometers (e.g., "listening" for leaks and/or leak paths), and
in the case of offshore installations pressure sensors sensing
depth. It is intended that the following claims be interpreted to
embrace all such variations and modifications.
* * * * *